Hybrid photovoltaic/thermal distributed power generation systems are fast becoming of new international importance as a fast growing segment in newly added power production, with intense research, development, installation and study efforts ongoing worldwide.
The use of concentrated solar power has a long history. The Greek mathematician, engineer and inventor Archimedes was said to have used what amounted to solar concentrators to bring incineration upon the invading Roman fleet of Marcus Claudius Marcellus in Syracuse in 212 BC. Concentrating solar power to produce heating and light effects continued throughout the Middle Ages.
Present day concentrated solar power (CSP) energy conversion systems use mirrors or lenses to concentrate a solar light onto a small area, yielding a number of well-known cost and efficiency and energy density advantages. If electrical power is desired, the concentrated light can be converted to high heat, and used to drive a heat engine, such as a steam turbine, that exploits a Carnot-family thermodynamic cycle process, such as Rankine and Stirling processes, as known in the art.
Such thermoelectric installations have spread around the world, with large installed capacities coming on line this past decade. Most of these plants are parabolic-trough plants, which concentrate light for impingement onto thermal tubes or collectors that contain a heat transfer medium. Large scale CSP plants achieve overall energy conversion efficiencies of approximately 17 percent. CSP plants, in order to meet engineering requirements for safety and longevity of the turbines or conversion equipment to which they are connected, often have to dump excess thermal energy, rather than use it for conversion. This is often done by judicious movement of solar tracking of the collector troughs, or by blocking or covering the thermal pickup(s).
CSP systems are distinct from concentrated photovoltaics (CPV). In CPV, the concentrated sunlight is converted directly to electricity via the photovoltaic effect. In either case, the characteristics of sunlight incident upon a converter are determinative.
Now referring to FIG. 1, a cartesian plot of both unfiltered solar radiation and net (ground) solar radiation is shown, with spectral radiance in watts per square meter per nanometer versus wavelength in nanometers (nm). Approximately seven percent of the electromagnetic radiation emitted from the sun is in a UV range of about 200-400 nm wavelengths. As the solar radiation passes through the atmosphere, ultraviolet or UV radiation flux for shorter wavelengths is reduced, absorbed in large part by atmospheric gases and stratospheric ozone, with a small amount transmitted to the Earth's surface. Solar UV-A radiation from 320-400 nm is essentially, for practical purposes, not absorbed by the ozone layer. As can be seen, a large span of wavelengths are present in a particular distribution in solar light. New efficient solar energy conversion systems very often use varied internal conversion components, and often operating strategies, for converting the various wavelength fractions as shown.
Photovoltaic energy conversion of visible light fractions typically makes use of the photovoltaic effect. Solar cells use this effect inside what are usually traditional solid-state semiconductors, formed by single or multiple lattices of semiconductor crystals with two alternating type of dopants—those doped with n-type impurities to form n-type semiconductors, which provide a free population of conduction band electrons, and those doped with p-type impurities to form p-type semiconductors, which add what are called electron holes. Electrons flow across the lattice boundaries to equalize the Fermi levels of the two differently doped materials. This results in what is called charge depletion at the interface, called the p-n junction, where charge carrier populations are depleted or accumulated on each side.
Sunlight can cause photo excitation of electrons on the p-type side of the semiconductor lattice, which can cause electrons from a lower-energy valence band to pass into a higher-energy conduction band. These electrons, after subtracting various energy and charge carrier losses, can do work across an electrical load as they flow out of the p-type side of the lattice to the n-type side. The result is a known and mature direct energy conversion process which offers relatively high conversion efficiencies, especially if light of selected wavelengths is selected for absorption.
Recently, energy efficiencies have gone up via a newer type of lattice construction using multiple junctions which are custom fabricated using different semiconductor materials and dopants to operate efficiently for selected wavelenegths. Development of these and other enhanced photovoltaic technologies, such as vertical multijunction (VMJ) photovoltaic cells, offer promise for concentrated solar photovoltaics. In a photovoltaic device, each semiconductor or other material can create a p-n junction or interface that produces charge carrier current in response to a select distribution of wavelengths of light. Such multijunction photovoltaic cells provide optimal light-to-electricity conversion at multiple or select wavelengths of light, which can increase overall energy conversion efficiency. Traditional single-junction cells have a maximum theoretical efficiency of 34%. Theoretically, multijunction photovoltaics have a maximum theoretical efficiency in excess of 50% under highly concentrated sunlight. In addition, high voltage silicon vertical multijunction photovoltaic solar cells made using recently developed fabrication techniques are ideally suited for beam-split concentrated light applications, as they are capable of conversion of light intensities of tens or hundreds or thousands of suns intensity AM1.5.
Structurally, VMJ cells are an integrally bonded series-connected array of miniature silicon vertical unit junctions. They offer design simplicity, low cost, and an innovative edge-wise entry for light that allows for easy and controlled absorption and conversion at the high energy levels produced by hydrid concentrated solar power. Their higher per-unit cost relative to single junction photovoltaics can be more than justified by their ability to handle and convert concentrated solar power and the high voltage they produce is more compatible electrically with conditioning systems that prepare the photovoltaic power for use upstream or for backfeeding into electrical utility transmission networks.
In forming hybrid systems, known beam splitting between thermal and and photovoltaic receivers is known in the art and has been a big factor driving hybrid energy conversion, as the lower frequency fractions of sunlight are typically used to drive thermally based processes, and the higher frequency fractions, namely, visible light and high energy infrared—are used to power photovoltaic systems. When used in this manner, overall energy conversion efficiencies of VMJ photovoltaic cells such as those made by MH Solar Co. (Kaohsiung City, Taiwan) can approach and surpass 35% when used to convert light from 400 nm to 1100 nm, rather than full received solar radiation, which includes background and longer wavelength infra-red light.
In forming hybrid PV/T systems that process separately the thermal and mostly visible portions of the solar spectrum, the prior art makes use of adaptive concentrators that can change the relative amount of received solar energy devoted to thermal versus photovoltaic uses.
For example, US Publication 2013/0255753 to Escher discloses a photovoltaic thermal hybrid system wherein a photovoltaic module and/or a thermal collector are moveably mounted. One method disclosed involves instructing a positioning mechanism to move the photovoltaic module and/or the thermal collector to change operatively a ratio of an intensity of radiation received at the photovoltaic module to that received at the thermal collector. This system, however is cumbersome, requiring a high ratio of moving components to solar energy collected, and is slow to react and change, which is a consideration discussed below.
The planning, design, adoption, regulatory approval for, and utility approval for the use and installation of hybrid PV/T solar energy conversion systems are all evolving. Aside from land use and environmental considerations, high capital costs and especially local utility grid infrastructure and engineering requirements are fast becoming major issues for the success and acceptance of such systems, particularly for those where backfeeding of electricity produced to generate revenue is expected to be significant.
Now referring to FIG. 2, a plot of spectral direct irradiance versus time for a typical sample summer day is shown in a cartesian plot. As can be seen from this plot over less than one hour time, large variations are the norm in incident light power, due to passage of clouds and haze and other atmospheric variations and photovoltaic power generation levels behave accordingly. These considerations are discussed in US Publication 2008/0295883 to Ducellier et. al., incorporated by reference herein in its entirety.
Many smaller distributed solar power generation systems have no storage capacity, and are typically used in residential homes and small businesses to either decrease the apparent load imposed on the electric utility, or there is what amounts to a purchase of excess energy by the utility, with backward metering, possibly with the electric billing meter spinning backwards, if mechanically based.
Many large commercial hybrid distributed power generation systems, have storage capacity for thermal energy produced, and backfeed local electrical utility electrical transmission lines for revenue generation, making use of metering agreements with utilities that can include net or reverse metering, TOU (Time of Use) metering or buy-back rates for electricity produced and sold to the utility. In buying power from distributed solar energy conversion plants, time-of-use rates often apply, and the utility often reduces the revenue by demand charges that may be assessed, as well as miscellaneous charges for reactive power being backfed into the electrical grid. All such distributed power generation systems back-feeding power into central or network electrical utilities must meet many engineering requirements and endeavor to help provide and maintain a stable electrical transmission grid, free from brown-outs, power outages, and electric waveform spikes and other abnormalities.
Many utility connected distributed solar power generation systems produce DC (direct current) voltages in excess of 300 volts before being transformed into inverted AC (alternating current) waveforms using known inverters. A proper AC waveform output from distributed power generation systems is needed for compatibility with the world's electrical power and transmission systems, and to enhance safety, because the fire hazards of DC circuits are great. For a given power level, a DC arc is harder to extinguish and causes more damage more quickly.
At central electrical utilities, a grid operator endeavors to match on-line generation capacity to customer electrical load at any given moment. The grid operator controls the deployment and call for generation output from all power producing assets, including network high voltage transmission lines to other utilities, to provide for electrical needs during load swings throughout the day. The recent additions worldwide of renewable energy generation technologies such as solar and wind power creates a class of power generation assets which relatively speaking, cannot be controlled or scheduled in the same way.
Naturally, there are requirements that must be met before any distributed generation plant can be allowed to be connected to a utility transmission grid. One such requirement is known as an anti-islanding provision. Islanding is undesirable creation of an island of distributed generation equipment that is attempting to power a grid location even though centralized electrical utility power is no longer present. To address this, universally there are line voltage monitoring systems in PV inverters/controllers that make sure that a photovoltaic system does not attempt to feed dead circuitry, to protect line personnel and others from the dangers of a back-feed onto the utility grid system upon utility power failure, circuit fault, or planned shut-down. This kind of safety requirement is actually part of a much larger set of strict engineering requirements imposed upon distributed power generation systems, including hybrid systems that are the subject of this disclosure. These requirements are codified in regulatory standards and codes, and more specifically in engineering policy at electrical utilities, and usually guided further by utility field engineering departments that have a yes or no say in approvals of new energy producing assets that will backfeed into their power networks.
In the United States the National Electrical Code has well-developed provisions like Article 690, which relate to safety of solar photovoltaic systems. Localities also typically reserve the right to check photovoltaic backfed power quality, including measurement of unwanted secondary, tertiary, and higher order harmonics that can cause electromagnetic interference, component overheating, low power factor and component and customer equipment failure. Harmonic electrical injection, including THD (Total Harmonic Distortion) into a grid is often limited to levels as stipulated in IEEE (Institute of Electrical and Electronics Engineers) Standard 519-1992. Other general standards include IEEE Standard 929-2000, entitled, IEEE Recommended Practice for Utility Interface of Photovoltaic (PV) Systems, covering anti-islanding, safety, and power quality, as well as provisions promulgated by testing and certification organizations, such as Underwriter's Laboratories (UL) Standard 1741, entitled, Inverters, Converters, Controllers and Interconnection System Equipment for Use With Distributed Energy Resources.
Furthermore the Energy Policy Act of 2005 established IEEE Standard 1547, Standard for Interconnecting Distributed Resources with Electric Power Systems, as a national standard in the United States.
These standards, as well as well-established engineering practice address other problems. Part of IEEE Standard 1547 addresses frequency drift, and mandates obligatory overfrequency disconnection at 60.5 Hz, and underfrequency disconnection at 59.3 Hz. The subject matter of this engineering is to handle adverse phenomena that occur and change from moment to moment.
The imposition of engineering standards that can doom the future of a hybrid distributed power generation plant can even be used to serve other objectives. There is an economic disincentive for electrical utilities to make large numbers of approvals for proposed distributed (independent) solar generation facilities, because, in part, the buybacks or purchases of power from these independent facilities provide negative capital flow without a proportionate contribution to cost of the transmission line infrastructure to which they connect. Traditional CSP plants are facing declining favor in the eyes of electrical utilities because of lack of controls over their production, which can exhibit choppy, intermittent, or even insidious mass-oscillating backfeed power levels. Utilities produce what is called a base production using large, cost-efficient, highly controlled and predictable power producing assets, such as hydroelectric or production or fuel-powered turbines which drive large generator sets. They typically supplement this with power purchased minute-by-minute from neighboring utilities, and with more expensive supplemental power generating assets.
Intermittent sources of electricity such as traditional flat panel single junction photovoltaics are difficult for utilities to manage. The fast changing supply into local transmission lines varies and can create a grid instability should excess capacity be forced on the grid.
In this disclosure, acceptance by utilities and meeting local in-place engineering requirements for both backfeeding electrical power and local cogeneration figure importantly. Those engineering requirements are numerous and stringent, driven in part by:    [1] Cloud passage, which causes introduction of significant amounts of fast-changing intermittent power generation added to the base load of a utility. This can affect operational controls across huge regions and can increase the need for what historically has been known as spinning reserve, where electromechanical power production assets must possess undue elasticity to meet demand fluctuations, reducing operating efficiency and increasing operating costs, by running more equipment than strictly necessary under ordinary operating conditions, or by running equipment faster or with greater torque than otherwise needed.    [2] Islanding, especially if there is large distributed power capacity in a particular region or neighborhood, as those systems provide a false reading of line voltage and continue to provide power after a utility fault or shutdown. IEEE Standard 1547 mandates that distributed solar power generation system inverters disconnect if there is a sagging voltage condition. However, since loads are not automatically disconnected, this may cause an increase in central utility demand to make up for the lost power, aggravating voltage sag perhaps further and leading to pre-blackout or blackout conditions, such as where a nominal 120 volts or 240 volts to ground residential service goes down to 108 or 216 volts, respectively as a result of these dynamic events.    [3] Insidious mass phenomena, as large numbers of individual distributed power generation systems can effectively work together in unintended ways, with slightly different backfed power frequencies combining using constructive and/or destructive interference, and triggering a non-linear oscillator on a grand scale that could wreak havoc with utility operations and equipment and damage customer assets as well.    [4] Escalation of short circuit or fault currents, as the addition of distributed power generation systems can add to fault current values, causing unplanned destruction of utility property and lines.    [5] Insidious action of utility fault current relays, as strange behaviors are induced. Electric utility fault relays have a certain protocol that gets triggered by detecting a circuit fault, such as when a tree branch causes two overhead phase conductors to touch. Typically there is a disconnect period to allow the fault to clear. If inverters remain online, for lack of responsiveness or any other reason, those inverters and associated controllers can get damaged during a fault current relay reconnect. Alternatively, the inverters may continue to supply current, which could maintain the circuit fault, causing the utility fault current relays to lock open or go into permanent cut-out. During that time, the inverter may continue energizing utility phase lines, causing a dangerous condition for customer equipment and a possible danger to utility line maintenance personnel.    [6] Distributed power generation systems as presently configured cause problems with voltage and current regulation. Utility voltage regulators measure current and voltage and will boost voltage to insure proper delivery standards are met after taking into account voltage drop in proportion to power flow. Introduction of a distributed solar power facility tends to distort the regulation scenarios, boosting impoperly delivered line voltage to surrounding customers, while potentially lowering customer line voltage if the regulation systems are being shown voltages boosted by injection of photovoltaic or solar-provided power.    [7] Fuses, cut-outs, circuit breakers and inductive limiters are all designed to protect utility lines, but injection of distributed power generation will not perhaps be detected, adding to overload potential.    [8] Phase-to-neutral voltages can spike, especially with load generation imbalance, with a robust solar distributed power generation station that is not equipped to react in a timely manner to prevent over-voltage, because present-day systems are limited in their dispatchability and/or interactive control capability.
One problem is that because energy production systems are naturally designed to be useful over a wide range of possible insolation levels, including seasonal variations, there often come times or operating conditions that warrant “dumping” excess power, either at the communicated or prior request of a local electric utility, or to protect on-site equipment or property.
Now referring to FIG. 3, a rough schematic representation of one prior art energy dump procedure for a hybrid photovoltaic/thermal distributed power generation plant is shown. As shown, a collector tracking angle or other similar parameter as known by those skilled in the art is changed (Change Collector Tracking Angle) which provides a defocus or other reduction in a concentrated solar beam (Defocus Concentrated Beam) and causes the plant to reduce solar input, shown, Reduce Solar Incidence. This practice is common, but wasteful and not adequately responsive to meet new engineering requirements.
As will be discussed, the shut-off or apportionment upon intelligent demand the energy flows from the thermal and/or the photovoltaic sources in a hybrid distributed power generating station can result in higher energy production from a set amount of solar input, and can alleviate or eliminate many adverse phenomena, allowing for increased acceptance by and compatibility with electric power utilities.
One objective of the instant invention is to provide dispatchability and fast, selective, on demand, interactive control capability that meets engineering objectives as discussed above. Other objectives include higher overall energy conversion efficiencies, higher revenue generation from backfed power, and other objectives, as will be evident reading the appended description.